1. Field of the Invention
The present invention relates to the problem of plugging transport lines with gas hydrates during the oil and/or gas production. It may also be applied to other fields such as those of drilling mud or of transporting gas in the form of hydrates.
It concerns a method for determining the gas hydrate anti-agglomeration power of a system composed of an aqueous phase dispersed in a liquid hydrocarbon phase in the presence of a gas.
Gas hydrates are crystalline compounds which may form under pressure and at low temperatures when water is in contact with gas molecules. Such conditions are generally encountered during the production of oil and/or gas, in particular under deepwater conditions. Formation of such hydrates can lead to the formation of a plug by an agglomeration mechanism. In the case of the presence of a liquid hydrocarbon phase (production of oil or condensate gas), water may be in the form of droplets dispersed in the liquid hydrocarbon phase. We then have a water-in-oil emulsion the stability of which is linked to the presence of natural surfactants or additives.
The invention proposes a method for determining the agglomeration of hydrates for systems essentially consisting of emulsified water-in-oil systems. This method, as was described above, is of interest to the production of oil and condensate gas, but also to drilling operations using oil-based mud constituted by an aqueous phase dispersed in an oily phase.
2. Description of Related Art
Operational solutions currently employed to prevent the formation of hydrate plugs in lines essentially consist of using thermally insulated lines or injecting thermodynamic inhibitors. In both cases, the production conditions are kept outside the hydrate stability zone. This stability zone, in terms of pressure and temperature, is determined from tests carried out in a PVT cell or by using thermodynamic models. More recently, a method using a high pressure calorimeter has been proposed (French patent FR-B-2 820 823) in the case of drilling mud.
More rarely, it has been envisaged to inject:                kinetic inhibitor additives (Corrigan A, Duncum S N, Edwards A R and Osborne C G, SPE 30696 presented at the SPE Annual Technical Conference and Exhibition, Dallas, Oct. 22-25, 1995);        or anti-agglomeration additives (AA) (Mehta A P, Herbert P B, Cadena E R and Weatherman J P, “Fulfilling the promise of low dosage hydrate inhibitors: Journey from academic curiosity to successful field implementation”, OTC 14057, Houston, Tex., 6-9 May 2002).        
Finally, problems linked to the formation of hydrate plugs can be expected to be avoided because of the presence of natural surfactants in the oil (Palermo T, Mussumeci A, Leporcher E: “Could hydrate plugging be avoided because of surfactant properties of the crude and appropriate flow conditions?” OTC 16681, Houston, Tex., 3-6 May 2004). AA (anti-agglomeration) additives and natural surfactants cannot prevent the formation of hydrate particles, but prevent the latter from agglomerating. Hydrate particles may thus be transported in the form of a suspension without the formation of a plug.
However, generalizing the concept of hydrate transport in the form of a suspension suffers from a lack of a simple, reliable evaluation means. The most highly developed means consist of tests carried out in flow loops approaching real conditions (Palermo T, Maurel P: “Investigation of hydrates formation and hydrates transportation with and without dispersant additives under multiphase flow conditions”, in Multiphase '99, 9th International Conference on Multiphase, 567-582). However, the difference in scale and the mode of circulation in a loop renders predictions of the risks of plugging under real conditions difficult. Such facilities also require very large quantities of fluid and are thus expensive to use.